In the petroleum industry, chemical treatment of a downhole formation is an established technique to improve the rate and amount of oil production. For example, hydrofluoric acid (HF) may be used in sandstone rocks to dissolve the rock or other solids, thereby providing a flow path for the formation fluid to flow through and be produced. For carbonate rocks, hydrochloric acid (HCl), organic acids, or a chelating agent such as ethylenediaminetetraacetic acid (EDTA) may be used to dissolve calcite (CaCO3) and serve the same purpose. Calcite reacts readily with HCl and dissolves, leaving behind a channel that acts as a conduit for the formation fluid to flow through and be produced. The high reactivity of CaCO3 to acids has made acidizing a common practice in carbonate reservoirs.
Although acidizing is very common, especially in carbonate formations, the treatment process is monitored in a very limited sense. The most common parameters monitored during a chemical (acid) treatment include injection pressure, injection rate, downhole pressures, and (more recently) distributed temperature, which can be related to the extent of the treatment. However, temperature monitoring, for example, is not particularly effectual, and if there is poor zonal coverage of chemical treatment, such poor zonal coverage may not be discovered until later, in the production phase, when a low production rate is experienced. It is important to be able to assess treatment efficiency during treatment operations to avoid poor zonal coverage, and to optimize the efficiency of the chemicals injected based on the formation properties encountered at that injection site.
The electrical resistivity of a formation is an important parameter in determining hydrocarbon and water saturation. Electricity can pass through a formation due to the conductivity of formation water. Dry rock is generally a very poor electrical conductor. Therefore, subsurface formations have measurable resistivities because of water (or injected fluids) in the porous media. The resistivity of a formation depends, at least in part, on: (1) the resistivity of the formation fluid; (2) the amount (or saturation) of water present; and (3) the pore structure geometry (e.g., pore shape and connectivity, wormhole, fracture). Formation resistivity is measured by sending a current into the formation and measuring the resulting voltage drop. The ratio of voltage to current equals the formation resistivity. In the field of well logging, the current may be directly injected into the formation or eddy currents may be induced in the formation by a varying magnetic field.